Apparatus and Method for Lateral Well Drilling

ABSTRACT

A downhole tool assembly for cutting laterally into an earthen formation from a wellbore. The downhole tool assembly includes a flexible tubing circumscribing a series of interconnectable drive segments which can rotate in at least 2 axes on each end, wherein the flexible tubing forms at least one tubular member inner passageway.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Provisional Application No. 61/573,777 filed on Sep. 13, 2011.

FIELD

The present invention relates to an apparatus and method for cutting wellbore components and/or earthen formation surrounding the wellbore. More specifically, the invention relates to an apparatus and method for mechanically cutting earthen formation surrounding the wellbore, and optionally, casing and/or cement disposed in the wellbore, through the use of a rotatable, mechanical cutting head assembly.

BACKGROUND

A multitude of wells have been drilled into earth strata for the extraction of oil, gas, and other material there from. In many cases, such wells are found to be initially unproductive, or may decrease in productivity over time, even though it is believed that the surrounding strata still contains extractable oil, gas, water or other material. Such wells are typically vertically extending holes including a casing usually of a mild steel pipe having an inner diameter of from just a few inches to over eight inches used for the transportation of the oil, gas, or other material upwardly to the earth's surface. In other instances, the wellbore may be uncased at the zone of interest, commonly referred to as an “openhole” completion.

In an attempt to obtain production from unproductive wells and increase production in under producing wells, methods and devices for forming a hole in a well casing, if present, and forming a lateral passage there from into the surrounding earth strata are known. For example, a hole in cased wells can be produced by punching a hole in the casing, abrasively cutting a hole in the casing, milling a hole in the casing wall or milling out a vertical section of casing. While more or less efficacious, such methods are generally familiar to those in the art. In openhole wells, the steps to form a hole in the casing are not required, but the methods for forming a lateral passage into the surrounding strata may be virtually identical to those used on cased well.

Under both the cased and uncased well scenarios, a type of whipstock is typically incorporated to direct the cutting head out of the wellbore and into the formation. The whipstock may be set on the end of production tubing. Because of the time and economic benefits, often the cutting tools are run on the end of coiled tubing. In at least one known conventional horizontal drilling method using coiled tubing, the cutting tool completes its transition to the horizontal direction over a radius of at least several feet and some methods require a radius of over 100 feet. The size of the radius stems primarily from the length and diameter of the cutting tools and the rigidity of the toolstring that must transition around the radius. Other known methods for creating horizontal drainage tunnels are able to transition a much tighter radius (e.g., within 4.5″ casing) by not attempting to pass relatively long and/or large diameter tools (e.g., a mud motor) outside of the wellbore. Instead most such methods utilize a flexible jetting hose with a specialized and relatively small nozzle head (e.g., less than a few inches long). Such methods may be efficacious, but typically suffer from a common problem that that they do not and/or cannot provide adequate torque to satisfactorily power a mechanical cutting means capable of cutting harder formation. Accordingly, these methods may be limited only to very soft formations.

Furthermore, most known methods and apparatus have also generally been unable to provide technically or commercially satisfactory results because of an accumulation of cuttings in the lateral passage. Many known apparatus utilizing a form of jetting nozzles have been found unable to produce a satisfactorily large hole in the strata and, even when directed at soft strata, have been found to hang-up when trying to advance the nozzle into the formation, which can be due to an accumulation of cuttings in the lateral passage.

In addition to the aforementioned, cuttings created from the lateral drilling process or materials in the wellbore can also be problematic. If the rat-hole of the wellbore (the portion beneath the work area) is not deep enough to accommodate these materials, the materials can fill the wellbore up to or above the elevation of the whipstock. This in turn, can effectively preclude the removal of cuttings from the lateral borehole being drilled as the cutting have nowhere to fall and hence cause a stop in forward cutting of the lateral borehole. Additionally, cuttings in the wellbore can fill-up so that repositioning of the whipstock, such as to a new zone of interest, movement of the whipstock cannot be done.

In view of the above, it would be desirable to have a cutting tool capable of being run on a wireline unit, on coil tubing or on jointed tubing or rod, the tool being capable of being run in a wellbore and capable of transitioning in a radius of less than about 36 inches to a substantially horizontal orientation, wherein the cutting tool is provided with sufficient torque to cut even hard formation, like dolomite. It would further be desirable to have a cutting system capable of rotating under mechanical means and wherein a fluid may be emitted from the cutting tool, or adjacent to the cutting tool, to provide assistance in the removal of cuttings from the lateral passage, to clean the cutting faces and/or to cool the cutting tool, and to reduce the occasions of the cuttings causing mechanical problems.

SUMMARY

An embodiment of the present invention is an apparatus for cutting laterally into an earthen formation from a wellbore that includes a series of interconnectable drive segments, wherein the interconnectable drive segments collectively form drive linkage, the drive linkage circumscribed by a flexible tubular member. The flexible tubular member is sized and configurable such that an attached cutting head assembly to the drive linkage and a fluid pumping source may be in fluid communication. Wherein a first drive linkage end portion is sized and configured to be attachable to a rotation means and a second drive linkage end portion operatively coupled to the cutting head assembly such that torque applied to the first drive linkage end portion by the rotational source may be translated to the cutting head assembly. Wherein the flexible tubular member can transmit fluid flow within the flexible tubular member to a location proximate the cutting head and the fluid flow can remove cuttings in the annulus between the flexible tubular member and the lateral borehole produced by the cutting head.

An embodiment of the present invention is a method for cutting laterally into an earthen formation from a wellbore utilizing the apparatus described above.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 illustrates a cross-sectional view of an openhole completed wellbore containing a whipstock prior to the use of the whipstock in conjunction with an embodiment of the present invention.

FIG. 2 illustrates a cross-sectional view of a cased wellbore containing a whipstock, wherein an embodiment of the present invention is deployed in the wellbore and is disposed to cut a lateral borehole thru a predefined hole in wellbore casing.

FIG. 3 illustrates a cross-sectional view of a cased wellbore containing a whipstock, wherein an embodiment of the present invention is deployed in the wellbore, guided through a guide channel in the whipstock, and has created a lateral borehole through the casing and cement and is proceeding into the earthen formation of interest.

FIG. 4A illustrates a plan view of an interconnected drive segment consistent with an embodiment of the present invention and consisting of male teeth or pins and mating female sockets (not shown) on opposing sides of the drive segment. FIG. 4B illustrates a cross-sectional view of generally cylindrical interconnected drive segments of FIG. 4A consistent with an embodiment of the present invention and showing the male teeth and mating female sockets. FIG. 4C illustrates a cross-sectional view of a series of interconnected drive segments positioned around the radius of whipstock and consisting of the configurations depicted in FIGS. 4A and 4B with optional secondary tubular member, in this case a hose, positioned inside one of the inner passageway of the drive segments and consistent with an embodiment of the present invention.

FIG. 5 illustrates views of an interconnected drive segment consistent with an embodiment of the present invention and, in this case, consisting of flexible tubular shaft system comprising a hose circumscribing eared-links connected with block and pin style allowing each joint to rotate in two planes.

FIG. 6 illustrates views of an interconnected drive segment consistent with an embodiment of the present invention and, in this case, consisting of a flexible tubular shaft system comprising a hose circumscribing a series of mated eared-links connected with pins that allow each joint to rotate only in one plane.

FIG. 7 illustrates views of an interconnected drive segment consistent with an embodiment of the present invention and, in this case, consisting of a flexible tubular shaft system comprising a hose circumscribing a series of pinned ball and socket drive joints.

FIG. 8 illustrates views of an interconnected drive segment consistent with an embodiment of the present invention and, in this case, consisting of a cutting head assembly with carbide inserts, for cutting lateral boreholes in hard production formations.

FIG. 9 illustrates views of an interconnected drive segment consistent with an embodiment of the present invention and, in this case, consisting of a cutting head assembly consistent with an embodiment of the present invention is depicted.

FIG. 10 illustrates an embodiment of the present invention.

FIG. 11 illustrates an embodiment of the present invention consisting of a wireline unit and high pressure pumping equipment positioned on a cased wellbore.

DETAILED DESCRIPTION

In an aspect of the current invention, an apparatus for cutting laterally into an earthen formation from a wellbore is provided. As used herein, the term “lateral” or “laterally” refers to a borehole deviating from the wellbore and/or a direction deviating from the orientation of the longitudinal axis of the wellbore. The orientation of the longitudinal axis of the wellbore in at least one embodiment is vertical, wherein such a wellbore will be referred to as a vertical wellbore or substantially vertical wellbore. However, it should be understood that the orientation of the longitudinal axis of the wellbore may vary as the depth of the well increases, and/or specific formations are targeted. As used herein, the term “strata” refers to the subterranean formation also referred to as “earthen formation.” The term “earthen formation of interest” refers to the portion of earthen formation chosen by the operator for lateral drilling. Such earthen formation is typically chosen due to the properties of the formation relating to hydrocarbons.

The present invention relates to an apparatus, system, and method for cutting laterally into an earthen formation. Optionally, the apparatus may be used for cutting laterally into cement disposed within the wellbore. Optionally, the apparatus may be used for cutting laterally into the casing and cement disposed in the wellbore. Using the apparatus to cut laterally through the casing, cement, and earthen formation is advantageous in that the number of trips of downhole can be reduced significantly. The apparatus may be used in cased wellbores or openhole wellbores. Optionally, the apparatus may be used in wellbores wherein the one or more hole may have already been created through the casing and/or cement.

Generally, the apparatus will be run to a depth in the wellbore suitable for the retrieval of hydrocarbons and/or other desired materials. The location of the lateral boreholes will be operator specific and may vary based on the needs and goals of the operator. The location of the lateral boreholes may also be determined by the location of the wellbore and the environmental properties of the surrounding strata.

In at least one embodiment, the apparatus is a downhole tool assembly including a cutting head assembly, a flexible tubular shaft member, and a drive linkage attached to a means of rotation. When in use in a wellbore, the downhole tool assembly can be connected to a spool assembly including a conduit that can be used to lower the downhole tool assembly inside the wellbore. For example, the downhole tool assembly may be connected to a fluid motor and coil tubing that can be lowered into a wellbore and operated so as to cause rotation of the drive linkage and cutting head. In another embodiment, the downhole tool assembly is coupled to jointed tubing or pipe and a pumping source, whereby the downhole tool assembly is in fluid communication with pumping equipment by virtue of the jointed tubing string. In another embodiment, the downhole tool assembly is operatively connected to pumping equipment and a slickline or e-line unit, which together allow for placement, operation and/or retrieval of the downhole tool assembly. In an embodiment, the downhole tool assembly is operatively connected to pumping equipment and tubulars which together can be used to control the operation of the downhole tool assembly.

One end portion, or first end portion, of a conduit or tubing run into the wellbore can be coupled to a fluid pumping source. Optionally, the second end portion of the conduit is coupled to the first end portion of the flexible tubular shaft member such that the fluid pumping source is in fluid communication with the flexible tubular shaft member. The fluid pumping source can be any conventional fluid pump capable of providing fluid pressures to the downhole tool assembly such that the downhole tool assembly is able to emit fluid from or near the cutting head. Optionally, the fluid may be emitted at a pressure from about 100 to 5000 psi. Optionally, the fluid may be pumped at a pressure from about 5,000 to about 15,000 psi. The flow rate of the fluid may range from about 4 to about 12 gallons per minute (gpm). In another embodiment, the operating flow ranges from about 10 to about 20 gpm. In a further embodiment, the operating flow ranges from about 15 to about 35 gpm. Nonlimiting examples of the fluid pumped from the fluid pumping source include nitrogen, air, foam, diesel, hydrochloric acid, water, formation brine, biocides, wettability agents, surfactants, and the like.

In an embodiment, the second end portion of the conduit is coupled to a rotational source in an embodiment of the present invention. In at least one embodiment, the rotational source can be a motor sized and configured to be run into the wellbore and capable of operating at the depth and conditions desired by the well operator. A nonlimiting example of such a motor is a mud motor, such as the 175R5640 manufactured by Roper Pumps. The motor can be operatively coupled to a first end portion of the drive linkage, discussed further below. The motor can be coupled to the first end portion of the drive linkage such that a torque generated by the motor is applied to the drive linkage, thereby causing the drive linkage to rotate consistent with the torque applied by the motor. The motor may be further configured such that the fluid pumping source may be in fluid communication with the first end portion of the flexible tubular shaft member, discussed more fully below. In another embodiment, the rotation source of the downhole toolstring may be a surfaced-based rotational source, such as a power swivel, which is used to rotate the downhole toolstring by virtue of rod or tubing connected to the downhole toolstring. In yet another embodiment, the rotational source connected to the downhole tool may be a DC motor, such as operated by an e-line unit.

Optionally, the downhole tools may include a vibration source. The vibration source may be sized and configured to impart vibrations to shake the cutting head assembly and/or flexible tubular shaft member to facilitate the removal of cuttings and allows the cutting head assembly to more effectively penetrate into and be retrieved from the earthen formation. Optionally, the vibration source may be attached to the drive linkage or cutting head assembly. Optionally, the vibration source may be derived directly from the rotational source. The rotational source may further include a transmission, wherein the torque or revolutions per minute (rpms) of the rotational source may be adjustable.

As discussed above, the downhole tool assembly includes a flexible tubular shaft member in at least one embodiment of the present invention. The flexible tubular shaft member includes a first end portion discussed above and a second end portion wherein the second end portion can be locating near the cutting head assembly. The flexible tubular shaft member may define at least one hollow tubular cavity, which may be referred to as a tubular member inner passageway. In at least one embodiment, a secondary tubular member defining an interior passageway (e.g., a hose) may be disposed within a tubular member inner passageway and further coupled to and in fluid communication with the cutting head assembly. In an embodiment used with a sealing mechanism, described in more detail below, the first end portion of the flexible tubular shaft member allows for internal to external porting whereby fluid can enter into the inside of the flexible tubular shaft member and optional secondary tubular member thereby allowing it to flow to the cutting head assembly.

Optionally, the flexible tubular shaft member includes one or more centralizing members that can enable it to be centralized with respect to the wellbore and/or lateral borehole. Non-limiting examples of centralizing members include radially oriented pins, brushes or springs.

In at least one embodiment, the downhole tool assembly may include an upper cross-over member connected to the first end of the flexible tubular shaft member. In at least one embodiment, the upper cross-over member has at least one passageway allowing for it to transmit fluid to the inside of the flexible tubular shaft member. In at least one embodiment, the upper cross-over member is coupled to a motor on the one side and to the flexible tubular shaft member on the other side, so as to allow for the transmission of torque to the drive linkage. In at least one embodiment, the upper cross-over member can both transmit torque, such as by threading or splines, and allow for the transmission of fluid through a passageway. In at least one embodiment, the upper cross-over member can be used to help tension a tensioning system, described in more detail below, used to keep the drive linkage segments engaged with one another. In at least one embodiment, the upper cross-over member utilizes a nut and/or spring to keep the drive linkage components engaged with one another. In at least one embodiment, the upper cross-over member can transmit torque, allow for the transmission of fluid, and be used to put tension on a tensioning system running within the flexible tubular shaft member to hold the drive linkage components engaged with one another.

In an embodiment, the drive linkage comprises a series of drive segments capable of transitioning through and transmitting torque around a radius of less than 36 inches. The series of drive segments can be sized and configured such that each drive segment engages at least one other drive segment whereby torque is transmitted from drive segment to drive segment. In an embodiment, the drive segments transmit torque through one or more pins or teeth on a side of each drive segment and a respective mating socket on an adjacent drive segment. In one embodiment, each drive segment is configured with both a male tooth and a female socket on each side of the drive segment. In either of the aforementioned arrangements, each drive segment is configured with both male and female parts. In at least one embodiment, there are at least two male teeth and two female sockets on each side of the drive segments. In an embodiment there are four teeth and four sockets on each side of the drive segments. Each drive segment has at least one opening, collectively defining at least one inner tubular passageway. Optionally, the drive segments can be connected by one or more hoses or cables used to as a tensioning system to hold the drive segments together, as more fully discussed below. The drive linkage comprising the drive segments are further sized and configured to transmit torque applied from the rotational source to the cutting head assembly such that the cutting head, discussed below, is supplied with sufficient torque to cut the intended earthen formation.

The flexible tubular shaft member that circumscribes the drive linkage segments forms at least one inner passageway that can transmit fluid. Nonlimiting examples of the flexible tubular shaft member are hose or braided hose, KEVLAR®, convoluted tubing, interlocking hose, semi-rigid tubing, and the like. The flexible tubular shaft member can be in fluid communication with the fluid pumping source and the cutting head assembly. The flexible tubular shaft member can be fed, or transitioned, through a whipstock and into the earthen formation with the drive linkage and cutting head. In an embodiment, the circumscribed flexible tubular shaft member, the series of drive segments, the tensioning system and the cutting head are rotated simultaneously. Optionally, the series of drive segments, the tensioning system and the cutting head are rotated simultaneously but are independent from the rotation, if any, of the circumscribed flexible tubular shaft member.

In certain embodiments the flexible tubular shaft member can be used with seals and/or bearings positioned at the cutting head to provide independent movement while enabling fluid communication between the opposite ends of the flexible tubular shaft member without regard to the drive linkage rotation. That is, in this fashion fluid communication can be established between the first end of the flexible tubular shaft member end and the second end of the flexible tubular shaft member end. In this embodiment, a sealing mechanism, such as elastomeric seals could allow for fluid to be pumped through the passageway within the flexible tubular shaft member.

In at least one embodiment, the drive segments are held in contact with one another by a tensioning system. The tensioning system may be comprised of one or more tensioning lines running from and affixed to the cutting head assembly on the one end and to an upper cross-over member, discussed below, on the other. Optionally, the tensioning line may be comprised of one or more hose(s) or cables(s). Non-limiting methods to put tension on the tensioning lines include affixing one end to the cutting head assembly, such as by a crimp or threaded connection and employing a tensioning mechanism on the other end. Optionally, the other end of the tensioning line may terminate in an upper cross over member, discussed below, wherein a tensioning mechanism, such as a crimp and adjustable nut, may be employed to set a predetermined amount tension on the tensioning line. Optionally, the tensioning line may connected to a spring, which can be preloaded and which may allow for varying amounts of tension to be placed on the tensioning line. Again, applying tension to the tensioning line will cause the drive segments to be held together since the opposing ends of the tensioning lines terminate beyond the opposing ends of the drive segments. Optionally, the tensioning line(s) may be situated around the axis of rotation of each drive segment (for example, at zero, 120 and 240 degrees) or it may be situated along the axis of rotation. In another embodiment, the tensioning line may lie inside the second tubular member situated inside the series of drive segments. In an embodiment, the tensioning lines may be situated about the exterior of the drive segments. An alternate embodiment also employs a tensioning line(s) affixed to the cutting head assembly on the one end and terminating at the upper cross over member on the other. In this embodiment, a spring in the upper cross over member may be used to push on the drive segments themselves thereby holding them together and wherein the pushing force terminates in the cutting head assembly by virtue of the tensioning line also terminating there. These and similar tensioning mechanism are intended to be within the scope of this application.

Embodiments of the present invention may include an upper cross over member, which may serve multiple purposes. As described above, it may serve as part of the tensioning system used to keep the drive segments of the flexible tubular shaft member engaged with one another. Additionally, the upper cross over member may allow for fluid communication to be established with the flexible tubular shaft member, whether by merely conveying fluid exiting a downhole motor into the flexible tubular shaft member or by diverting flow from the upset tubing by virtue of a sealing mechanism. Finally, the upper cross over member may provide a means of transferring torque from a rotational source to the drive linkage, such as by splines or threading.

Optionally, an exterior surface of the flexible tubular shaft member defines one or more flutes, grooves or rifling, which can facilitate cuttings from the lateral borehole to flow past the flexible tubular shaft member and up the wellbore.

In an embodiment, the cutting head assembly includes a cutting head, wherein the cutting head can be detachably attached to the cutting head assembly and further configured to be rotatable and to cut laterally through casing, cement, and/or earthen formation. Optionally, the cutting head assembly defines a cutting head sized and configured to cut laterally through casing, cement, and/or earthen formation. The cutting head can form one or more recesses within the cutting head assembly to allow for some or all of the following: to provide placement of the one or more exit orifices for the fluid flow, to allow for efficient cutting of the formation and/or to allow provide a passageway for cutting to be removed from the cutting head area. The cutting head includes one or more cutting surfaces or faces, and may be configured such that one or more orifices may be able to eject fluid, gas or a combination thereof near the cutting surface(s) or face(s). A cutting face may circumscribe a portion of a rotatable nozzle, or a plurality of cutting faces may collectively circumscribe a portion of a rotatable nozzle. The cutting head can be continuous or segmented (e.g. serrated). The cutting face(s) can be formed from a material of sufficient hardness for cutting the intended earthen formation and/or casing and cement. For example, at least a portion of the cutting face may be formed from carbide or diamond.

The cutting head can be defined by the cutting head assembly or fixedly attached or can be detachably attached to the cutting head assembly. A non-limiting example of a detachable attachment is conventional threading. In an embodiment, the cutting head is detachably attached to the cutting head assembly, wherein the cutting head assembly includes one or more bearings or the like to facilitate rotation of a rotatable nozzle. The bearing may be a mechanical bearing, such as a bronze bushing, needle bearing, or ball bearing. Optionally, the bearing may be a fluid bearing, wherein a fluid bearing may be created upon the pumping of a fluid into the flexible tubular shaft member and cutting head assembly. Optionally, the fluid and/or mechanical bearings may be used in conjunction with seals.

The cutting head assembly defines one or more head assembly openings in an embodiment of the present invention. The head assembly openings can be sized and configured to permit fluid flow there through. The cutting face may define one or more cutting face openings and the interior face surface may define one or more cutting face openings, wherein the cutting face opening is in fluid communication with the fluid pumping source. Fluid flow through the head assembly openings can be used to keep the cutting head cool, facilitate the removal of cuttings from the borehole, and/or impart rotation of the cutting head and/or rotatable nozzle.

Optionally, the cutting head assembly and/or the circumscribed flexible tubular shaft member, includes one or more centering members sized and configured to retain the cutting head assembly centrally located along the longitudinal axis of a borehole created by the apparatus when engaged in cutting laterally into the earthen formation. Non-limiting examples of suitable centering members include bow springs, brushes, pins, and fluids. The centering member also may function to allow cuttings and fluid or gases emitted from the cutting head assembly to readily pass the cutting head assembly and move toward the wellbore.

In an embodiment, the pressure of the fluid at the nozzle openings is greater than about 100 psi. The fluid pumped through the nozzle openings may accomplish one or more of the following: keeping the cutting head cool for cutting face longevity, keeping the cutting faces clean for efficient formation drilling, providing a carrying medium for transporting of cutting toward the wellbore, ejecting chemicals used to better dispose the formation to mechanical cutting, or to inject a chemical (e.g., biocides, inhibitors, wettability modifiers, etc.) to treat the formation adjacent to the lateral borehole.

As stated above, the cutting head assembly can be connected to the second end portion of the drive linkage, wherein a motor can be connected to the first end portion of the drive linkage, such that the drive linkage is rotatable when the motor is engaged. In an embodiment, the motor can be driven by the flow of fluid from the conduit, thereby causing the drive linkage to rotate, wherein at least a portion of the fluid used to drive the motor is transmitted by the drive linkage, located within the flexible tubular shaft member, to the cutting head assembly and/or nozzle. Optionally, the motor may be driven by the flow of fluid from the conduit, thereby causing the flexible tubular shaft member to rotate and fluid from the fluid pumping source is pumped through the secondary tubular member to the cutting head assembly in order to drive the rotatable nozzle and/or cutting head.

Turning now to a system and method for cutting laterally into an earthen formation from a wellbore, a whipstock is employed in at least one embodiment of the present invention. As used herein, the term “whipstock” refers to any downhole device capable of positioning the cutting head assembly toward the earthen formation desired for lateral cutting. The whipstock defines a guide channel sized and configured to receive and guide the cutting head assembly, drive linkage, and at least a portion of the flexible tubular shaft member through the whipstock and proximate the earthen formation of interest. In at least one embodiment, the whipstock may guide the cutting head assembly into a substantially horizontal direction from a vertical wellbore such that the cutting head assembly is disposed approximately 90 degrees from the longitudinal axis of the wellbore. The whipstock may be disposed in the casing prior to the running of the downhole tool assembly. Optionally, the whipstock may be set with a coil tubing unit, on the end of production tubing or it may be set by a wireline unit. The whipstock may have one or more passageways running through it that allow cuttings from the lateral borehole to fall toward the bottom of the wellbore.

Optionally, the flexible tubular shaft member may comprise a section that is adaptable to the whipstock and forms a seal with the whipstock. This seal may restrict the backflow of fluid and materials up the whipstock so as to seal out any cuttings washing back from the lateral borehole. This may be desirable in order to prevent cuttings from clogging the guide path of the whipstock, which could inhibit the free travel of the flexible tubular shaft member.

Optionally, the guide assembly may have one or more passageways extending from the guide path to below the whipstock to allow cuttings to freely fall toward the bottom of the wellbore.

Optionally, the bottom hole assembly may define one or more circulation passageways traversing from above the whipstock to below the whipstock, allowing for cleanout of the wellbore. In an embodiment, the circulation pathway(s) may extend around the whipstock, connecting to the upset tubing on the one end and to a passageway through the center of a packer on the other end. In another embodiment, they extend through the bottom of the whipstock and also serve to as the passageway(s) used to allow cuttings to freely fall from the guide path toward the bottom of the wellbore. The passageway(s) may serve as a circulation path for fluid that is circulated through the wellbore for the removal of cuttings, sand, paraffin and other materials that may have accumulated in the wellbore below the whipstock. For example, it may be necessary to remove cuttings from below the whipstock in order to allow the bottom hole assembly to be repositioned to a lower zone of interest for the creation of another lateral. Additionally, cleaning out any cutting in the wellbore maybe necessary for the proper operation of the packer. In an embodiment, the circulation opening(s) extend around the whipstock to a location at the end of the bottom hole assembly located 5 feet below the whipstock. Pumping of fluid to circulate the wellbore through these opening(s) may be done initially, periodically or continuously. In an embodiment, maximum circulation velocity is attained by retracting the downhole tool string into the primary wellbore (e.g. into the upset tubing). In this fashion, unobstructed flow through the circulation passageway(s) is best created, allowing for optimal wellbore cleanout. Cleaning out the wellbore and unloading the well may be accomplished by pumping fluid or gas at sufficiently high pressure and volumes through one or more of the circulation passageways.

Optionally, the system may be used with a form of containment system for the flexible tubular shaft member/drive linkage combination. This system may be comprised of a series of collapsible cups, stackable centralizers or sheathing. The purpose for this system is to allow for the efficient transference of weight from the top of the drive linkage to the bottom of the drive linkage by preventing the flexible tubular shaft member/drive linkage combination from forming a helical path or buckling when weight is applied to it from above.

The flexible tubular shaft member/drive linkage combination connected to the cutting head assembly can be fed, or transitioned, through a whipstock, such that the cutting head of the cutting head assembly is positioned proximate the earthen formation of interest for lateral cutting. Optionally, the cutting head is positioned proximate the portion of the casing and/or cement proximate the earthen formation of interest for lateral cutting. In an embodiment, the motor coupled to the first end portion of the drive linkage is actuated, whereby torque is generated by the motor and applied to the drive linkage and to the cutting head. The cutting head of the cutting head assembly rotates from the torque applied to the cutting head assembly and, in turn, the cutting faces contact the earthen formation, thereby cutting into the formation forming a lateral borehole. Optionally, the cutting faces contact the casing and/or cement in wellbore environments wherein openings have not been pre-drilled in the casing and/or cement proximate the earthen formation of interest. Fluid flow through the flexible tubular shaft member is discharged proximate the cutting head and flows out of the annulus between the flexible tubular shaft member and the lateral borehole. Cuttings are removed from the lateral borehole with the fluid flow exiting the lateral borehole. This embodiment keeps the cuttings isolated from the drive linkage and thereby reduces the chances for a cutting to become wedged between adjacent drive sections and inhibiting their rotational motion.

Optionally, a nitrogen generator at the surface may be provided and used in conjunction with the flexible tubular shaft member to clean out cuttings from the lateral borehole and/or wellbore. Optionally, pumping pressure and volumes may be sufficiently high so as to allow the nitrogen and cuttings to be lifted back up the wellbore; the nitrogen may then be circulated back to the generator, and the process may be repeated. Optionally, the nitrogen may be pumped through a downhole motor and to the cutting head. This closed loop nitrogen system is cost beneficial since a smaller system may be used and the need for a fluid pump including liquids may be eliminated.

In an embodiment, a wellbore including a whipstock set at the desired depth in the wellbore is equipped with a fluid pumping source and a coil tubing unit including a spool of coil tubing, wherein a first end portion of the coil tubing is coupled to the fluid pumping source, and the second end portion of the coil tubing is coupled to a rotational source. The rotational source can be a motor as discussed above. The motor in this embodiment is attached to a downhole tool assembly including a cutting head assembly and a drive linkage, wherein the fluid pumping source, coil tubing, drive linkage, flexible tubular shaft member, and cutting head assembly are in fluid communication. The coil tubing including the coupled motor and downhole tool assembly are lowered into the wellbore wherein at least a portion of the downhole tool assembly contacts the whipstock and is guided into the guide channel and positioned proximate the earthen formation of interest.

Optionally, the second end portion of the coil tubing is coupled to the downhole tool assembly such that the coil tubing is in fluid communication with the downhole tool assembly. The fluid pumping source can be coupled to the first end portion of the coil tubing in this embodiment. The coil tubing coupled to the downhole tool assembly is lowered into the wellbore wherein at least a portion of the downhole tool assembly contacts the whipstock and is guided into the guide channel and positioned proximate the earthen formation of interest.

Having described many of the apparatus of the present disclosure, let us further discuss the methods by which they system may be conveyed through the pre-positioned whipstock.

In an embodiment wherein a whipstock is disposed in a wellbore, a coiled tubing and pumping equipment can be connected to the upper end of the tool string such that fluid pumped through the coiled tubing can drive a fluid motor and the attached drive linkage and cutting head assembly. Now under rotation, the drive linkage and attached cutting head can be directed out of the wellbore by the pre-positioned whipstock in order to cut a lateral borehole in the surrounding earthen formation. Optionally, the drive linkage and attached cutting head may be used to through the casing and cement, if present, and proceed to cut into the surrounding earthen formation.

In an embodiment, wherein a whipstock is disposed in a wellbore and is coupled to a section of upset tubing, a slickline unit, such as familiar to those in the industry, can be used to position and control the travel of the downhole tool assembly. In this embodiment, a fluid driven motor is connected to the end of the slickline string on the one end and the flexible tubular shaft member and attached cutting head on the other end. The system can include one or more elastomeric sealing mechanisms positioned on or above the motor; the elastomeric mechanisms forming a relatively complete seal with the upset tubing. The sealing mechanism diverts fluid flowing through the upset tubing into the fluid motor, thereby causing the motor and attached drive linkage to rotate. Now rotating, the toolstring can be lowered so as to allow the cutting head to cut into the formation. Fluid flow through the flexible tubular shaft member is discharged proximate the cutting head and flows out of the annulus between the flexible tubular shaft member and the lateral borehole. Cuttings are removed from the lateral borehole with the fluid flow exiting the lateral borehole. This embodiment keeps the cuttings isolated from the drive linkage and thereby reduces the chances for a cutting to become wedged between adjacent drive sections and inhibiting their rotational motion.

In an embodiment wherein a whipstock is disposed in a wellbore, a wireline unit, such as familiar to those in the industry, can be used to position and control the travel of the downhole tool assembly. In this embodiment, an electrically driven motor is connected to the end of the wireline on the one end and to the drive linkage, circumscribed by a flexible tubular shaft member, and attached cutting head assembly on the other. This system can include one or more elastomeric sealing mechanisms positioned on or above the motor; the elastomeric mechanisms forming a relatively complete seal with optional upset tubing. The sealing mechanism diverts fluid flowing through the upset tubing into the flexible tubular shaft member and to the cutting head. Now rotating, the tool string can be lowered so as to allow the cutting head to cut into the formation.

In an embodiment wherein a whipstock is disposed in the cased wellbore and a wireline unit, such as familiar to those in the industry, can be used to position and control the travel of the downhole tool assembly. In this embodiment, an electrically driven motor is connected to the end of the wireline on the one end and to the drive linkage and attached cutting head assembly on the other. This system can include one or more elastomeric sealing mechanisms positioned on or above the motor; the elastomeric mechanisms forming a relatively complete seal with optional upset tubing. The sealing mechanism diverts fluid flowing through the upset tubing into the flexible tubular shaft member and to the cutting head. Now rotating, the tool string can be lowered so as to allow the cutting head to cut into the formation.

In an embodiment a pumping equipment and jointed tubing, positioned by drilling or work-over equipment, can be connected to the upper end of the tool string such that fluid pumped through the jointed tubing can drive a fluid motor and the attached drive linkage and cutting head assembly. Now under rotation, the drive linkage and attached cutting head can be directed out of the wellbore by the pre-positioned whipstock in order to cut a lateral borehole in the surrounding earthen formation. Optionally, the drive linkage and attached cutting head may be used to through the casing and cement, if present, and proceed to cut into the surrounding earthen formation. Fluid flow through the flexible tubular shaft member is discharged proximate the cutting head and flows out of the annulus between the flexible tubular shaft member and the lateral borehole. Cuttings are removed from the lateral borehole with the fluid flow exiting the lateral borehole. This embodiment keeps the cuttings isolated from the drive linkage and thereby reduces the chances for a cutting to become wedged between adjacent drive sections and inhibiting their rotational motion.

Referring to FIG. 1, in an embodiment an openhole completion (2) with a whipstock (1) having a guide path (3) is positioned in an open-hole completed well secured on tubing (4), which can be for example upset or production tubing. A pathway (5) around the whipstock (1) is shown to allow circulating fluid (6) to clean or wash out cuttings (not shown) from below the whipstock (1) and up the annulus (7) toward the surface. The deviation of a portion of the fluid (6) from the tool string (not shown) can create a turbulence in the rathole (8) and suspend the light cuttings and debris in the fluid to be carried towards the surface. This cleaning process helps to prevent the accumulation of debris in the rathole (8) and acts as a cleaning media for removing cuttings from the area around the whipstock (1).

Looking now at FIG. 2, in an embodiment a whipstock (1) is positioned on a packer (15) in a well with casing (16) through an earthen formation (17) and connected to tubing (4). A DC motor (18), with power supplied through an e-line (19), drives a flexible tubular shaft system (21) allowing the attached cutting head (22) to cut a hole (23) in the casing (16), and eventually, the cement (24) and earthen formation (17). Placeable and removable seals (26) between the toolstring, which can include, but is not limited to, the DC motor (18), flexible tubular shaft system (21), and cutting head assembly (22), and the tubing (4) can be used to divert fluid (6) pumped down the upset tubing (4) into, by way of one or more orifices (63) located above the seals (26), the flexible tubular shaft system (21) where it exits the cutting head (22) (as shown by arrows). A passageway (25) for circulating cuttings (not shown) from below the whipstock (1) traverses through the bottom of the whipstock (1) and packer (15).

FIG. 3 illustrates an embodiment wherein a flexible tubular shaft system (21) connected to a fluid motor, or positive displacement motor (30) is attached to a conduit, such as coiled tubing (31). Fluid (6) exits the fluid motor (30), traverses the flexible tubular shaft system (21) and exits the cutting head (22), as shown by arrows (23). The flexible tubular shaft system (21) with cutting head (22) has cut a hole in the casing (16), cement (24) and is cutting the lateral borehole in the production formation.

Referring to FIG. 4A-4C a flexible tubular shaft system (21) comprising a hose (35) circumscribing a series of nestable drive segments (36) with male teeth (37) on one side and female sockets (38) on the other side of each drive segment (36) and having an inner passageway for a tensioning cable (39) used to hold the nestable drive segments (36) in contact with one another. Fluid (6) traverses in the annular space (40) between the nestable drive segments (36) and the hose (35) which circumscribes them, while torque is transmitted from nestable drive segment (36) to nestable drive segment (36) by virtue of the male teeth (37) and female sockets (38).

Referring FIG. 5A-5D, the flexible tubular shaft system (21) comprising a hose (35) circumscribing eared-links (41) connected with block (42) and pin (43) style (universal joint) connectors, also known as universal joint or joint (combination of 42 & 42), allowing each joint (42 & 43) to rotate in two planes (44). Fluid (6) traverses through the annular space (40) between the eared links and the hose. Torque is transmitted from eared-link (41) to eared-link (41) by virtue of the universal joint (42 & 43), links wherein the mating ends of adjoining links comprise a universal joint allowing the rotation of the connection about 2 axes on each.

Referring to FIG. 6A-6D the flexible tubular shaft system (21) comprising a hose (35) circumscribing a series of mated eared-links (41) connected with pins (43) that allow each joint to rotate only in one plane (44). Fluid (6) traverses in the annular space (40) between the eared links (41) and the hose (35). In this embodiment, one side of the eared-links has a single ear while the opposing side of the eared-link has two ears (45); and, the sets of ears (45) are disposed at 90 degrees to one another. Torque is transmitted through the sets of ears (45) that have been pinned together and rotate on one plane (44).

Referring to FIG. 7A-7C a flexible tubular shaft system (21) comprising a hose (35) circumscribing a series of pinned ball and socket drive joints (47). A fluid passageway or annular space (40) between the hose (35) and the ball and socket drive joints (47) allows fluid (6) to flow to the cutting head (not shown). The crisscross slot and pin (48), used to transmit the torque along the series of ball and socket drive joints (47), are shown from different views in FIGS. 7A, 7B and 7C. In one embodiment the mating ends of adjoining links comprise a ball on one side and a socket on the other, wherein the adjoining ball and sockets can be joined together by a pin and socket mechanism allowing rotation in multiple axes on each end.

Referring to FIGS. 8A & 8B is a cutting head assembly (22) with carbide inserts (49), for cutting lateral boreholes in hard production formations (not shown). Evident on the cutting head assembly (22) are the cutting face (50) and the nozzle head (51) situated in a recess open to the exterior of the cutting head assembly (22). In this embodiment, rotation of the cutting head assembly (22) occurs by virtue of the nestable drive segments (36), which mate into the cutting head assembly (22). Fluid (6) travels down the annular space (40) between the hose (35) and the nestable drive segments (36) then enters the cutting head assembly (22) by passageways (52) where it subsequently exits the cutting head assembly through the nozzle orifices (53) so as to clean the cutting faces (50).

Referring to FIG. 9A a frontal view of a cutting head assembly (22) consistent with an embodiment of the present invention is depicted. Evident on the cutting head assembly (22) are diamond inserts (54) on the cutting faces (50) for improved cutting of lateral boreholes of the production formation (not shown); also the nozzle orifice (53) for the fluid (6) can be seen in the center of the cutting head assembly (22). As shown by arrow (55) indicating direction of rotation, behind the cutting faces (50) are back support areas (56) which provide structural support to the cutting faces (50) so as to resist breakage of the cutting faces (50) when cutting lateral boreholes in the production formation (not shown). In FIG. 9B a lateral borehole in production formation (17) is shown containing an embodiment of the flexible tubular shaft system (21), in this case a block (42) and pin (43) style universal joint, used to transmit torque to the mechanical cutting head assembly (21). Fluid (6) exiting the nozzle keeps the cutting faces clean and cool and provides a medium for carrying cutting back to the wellbore.

Referring to FIG. 10, this illustration is a cross sectional view of an embodiment of the present invention wherein a whipstock (1) deployed on tubing (18) in an open-hole completion (2) in a wellbore (9). The wellbore (9) is cased with casing (16) down to the production formation (17) area. The guide path (3) is orientated toward the production formation (17). In this embodiment, the downhole tool assembly (57), consisting of, but not limited to, a flexible tubular shaft system (21), cutting head assembly (22) and a fluid motor (30) is being operated by a coiled tubing unit (58), with pumping equipment that can produce sufficient pressure and flow to rotate a fluid motor which rotates the flexible tubular shaft system (21) and attached cutting head (22). Fluid (6) is pumped into the coiled tubing (59) and flows down through the fluid motor (30) and the flexible tubular shaft system (21) and exits the cutting head assembly (22) as shown by arrows.

Referring to FIG. 11 a wireline unit (60) and high pressure pumping equipment (61) positioned on a cased wellbore (9) in an embodiment of the present invention. In this embodiment, the downhole tool assembly (57) is positioned above a whipstock (1) and is connected to upset tubing (18) which, in this case, also serves as a conduit to carry fluid (6), shown by arrows, from the high pressure pumping equipment (61) to the fluid motor (30) and attached flexible tubular shaft system (21). Seals (26) between the fluid motor (30) and the upset tubing (18) direct fluid (6) into the fluid motor (30) which in turn causes the attached flexible tubular shaft system (21) and cutting head assembly (22) to rotate. The fluid (6) traverses the flexible tubular shaft system (21) and then exits the cutting head assembly (22) through the nozzle orifices (not shown). The downhole tool assembly (57) is lowered by the wireline unit (60) until the flexible tubular shaft system (21) enters and cutting head assembly (22) enters and passes into and through the whipstock (1) via the guide path (3) until the cutting head assembly comes in contact with the casing (16).

As used herein, the term “hose” refers to elastomeric hose, single or multi-braided hose, sheathed hose, Kevlar® hose and comparable means of providing a means for fluid conduit.

As used herein, the terms “wire” or “cable” refers to wire and cable whether single or multi-stranded, wire rope and similar means for securing or providing tension between two ends.

As used herein, the term “fluid” refers to liquids, gases and/or any combination thereof.

Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.

Depending on the context, all references herein to the “invention” may in some cases refer to certain specific embodiments only. In other cases it may refer to subject matter recited in one or more, but not necessarily all, of the claims. While the foregoing is directed to embodiments, versions and examples of the present invention, which are included to enable a person of ordinary skill in the art to make and use the inventions when the information in this patent is combined with available information and technology, the inventions are not limited to only these particular embodiments, versions and examples. Other and further embodiments, versions and examples of the invention may be devised without departing from the basic scope thereof and the scope thereof is determined by the claims that follow. 

1. An apparatus for cutting laterally into an earthen formation from a wellbore comprising: a flexible tubular member comprising a flexible tubing circumscribing a series of interconnectable drive segments which can rotate in at least 2 axes on each end, wherein the flexible tubing forms at least one tubular member inner passageway, the flexible tubular member being sized and configurable such that an attached cutting head assembly, the at least one tubular member inner passageway, and a fluid pumping source may be in fluid communication, and wherein a first flexible tubular member end portion is sized and configured to be attachable to a rotation means and a second flexible tubular member end portion is operatively coupled to the cutting head assembly such that torque applied to the first flexible tubular member end portion by the rotational source may be translated to the cutting head assembly.
 2. The apparatus of claim 1, wherein the cutting head assembly comprises at least one cutting surface sized and configured to mechanically cut into the earthen formation and wherein the cutting head assembly comprises a nozzle having at least one orifice for the ejection of fluid, gas or combination thereof positioned on or near the cutting head assembly and capable of being in fluid communication with the fluid pumping source.
 3. The apparatus of claim 1, wherein the flexible tubing comprises an inside and an outside and when the cutting head assembly is engaged in cutting into the earthen formation cuttings from the earthen formation may travel on the outside of the flexible tubing toward the wellbore and thereby be separated from the interconnectable drive segments.
 4. The apparatus of claim 1, wherein the interconnectable drive segments are held together, one to another, either by pin and mating socket mechanisms or collectively by a common tensioning means.
 5. The apparatus of claim 1, wherein the wherein the flexible tubing is selected from the group consisting of an elastomeric material, hose, braided-hose, flexible tubing, KEVLAR®, tubing, convoluted tubing, interlocking hose, semi-rigid tubing, and combinations thereof.
 6. The apparatus of claim 1, further comprising flutes, grooves or fins on the flexible tubing to facilitate the removal of cuttings from a borehole created upon rotational movement of the cutting head assembly into an earthen formation.
 7. The apparatus of claim 1, wherein at least one of the flexible tubular member ends comprises a seal capable of providing a substantially leak-proof fluid conduit between the pumping source and the cutting head assembly.
 8. The apparatus of claim 1, wherein at least one of the flexible tubular member ends comprises a bearing mechanism capable of enabling a substantially smooth rotation of the interconnectable drive segments within the flexible tubing.
 9. The apparatus of claim 1, wherein the interconnectable drive segments and the flexible tubing are capable of independent rotation.
 10. The apparatus of claim 1, comprising two or more interconnectable drive segments each having a base plane situated generally perpendicular to an axis of rotation and having at least two male teeth generally positioned on at least one side of the base plan and having at least two female sockets generally positioned on the opposing side of the base plane, such that the at least two male teeth on one side of the base plane of an interconnectable drive segment can mesh into at least two mating female sockets on an adjacent interconnectable drive segment thereby permitting the articulation and transference of torque of the flexible tubular shaft member around a radius.
 11. The apparatus of claim 1, wherein the flexible tubular member is deployed within a wellbore by means selected from the group consisting of production tubing, wireline, slickline unit, coiled tubing, and combinations thereof.
 12. The apparatus of claim 1, further comprising a rotational source selected from the group consisting of a fluid-driven motor, an electrical motor, or combinations thereof.
 13. The apparatus of claim 4, wherein the tensioning system is selected from the group comprising: the placement of a preload on a hose running through an inner passageway of the flexible tubular shaft member; the placement of a preload on a cable(s) running through an inner passageway of the flexible tubular shaft member; the incorporation of a spring situated above the interconnectable drive segments wherein the spring pushes the interconnectable drive segments together, or pulls the interconnectable drive segments together by pulling tension on a hose, wire or cable(s) running through an inner passageway of the interconnectable drive segments; and combinations thereof.
 14. The apparatus of claim 1, further comprising a whipstock comprising an internal guide channel to guide the flexible tubular member.
 15. The apparatus of claim 14, wherein the whipstock comprises a passageway through which formation cuttings can pass from the cutting head assembly to a location below the whipstock.
 16. The apparatus of claim 1, further comprising a sealing apparatus used in conjunction with a wireline unit allowing fluid communication with surface pumping equipment, said sealing apparatus providing a sealing mechanism between a fluid motor and a tubular extending to the surface through which fluid can be pumped, said sealing mechanism diverting flow from the surface pumping equipment through said tubular and into the fluid motor causing rotation of the motor and attached interconnectable drive segments and ultimately cutting head assembly, said motor connected to a wireline whereby the flexible tubular member may be lowered so as to create a lateral borehole in the earthen formation.
 17. A method for cutting laterally into an earthen formation from a wellbore comprising: guiding a downhole tool assembly comprising a flexible tubular member having a flexible tubing circumscribing a series of interconnectable drive segments which can rotate in at least 2 axes on each end, wherein the flexible tubing forms at least one tubular member inner passageway, through a channel defined by a guide assembly and positioning the downhole tool assembly so that the downhole tool assembly contacts a portion of the earthen formation to be laterally cut, wherein the downhole tool assembly is coupled to a conduit, such that the conduit and downhole tool assembly are in fluid communication; pumping one or more fluids through the conduit and into the downhole tool assembly; rotating a cutting head of the downhole assembly; and cutting a borehole into the earthen formation with the cutting head in a direction lateral to the wellbore.
 18. The method of claim 17, wherein the downhole tool assembly is operatively connected to a rotational source and the rotational source is coupled to a conduit, such that the conduit, rotational source, and downhole tool assembly are in fluid communication; activating the rotational source, wherein a torque is applied to the interconnected drive segments forming a flexible tubular member; and translating the torque to a cutting head of the downhole tool assembly, wherein the torque causes the cutting head to rotate.
 19. The method of claim 17, wherein the downhole tool assembly further comprises a nozzle on the cutting head defining one or more openings in fluid communication with the tubular member inner passageway, wherein the method further comprises: pumping one or more fluids through the tubular member inner passageway; and emitting the pumped fluid from the nozzle openings on the cutting head.
 20. The method of claim 19, wherein the nozzle openings comprise one or more orifices selected from the group consisting of a nozzle orifice at the center of the cutting head, a nozzle orifice(s) that are situated about the radius of the axis of rotation of the nozzle head, a rotating nozzle, a pulsing nozzle, a nozzle that creates a swirling pattern in its discharge flow, a nozzle designed to produce cavitation, and combinations thereof.
 21. The method of claim 17, wherein fluid is pumped through a fluid motor so as to rotate the flexible tubular member and the cutting head so as to cut earthen formation.
 22. The method of claim 17, further comprising forming a lateral borehole through a pre-existing hole in a casing; said hole created by one or more of the following methods: milling out the section of casing, abrasively cutting the casing, punching through the casing, cutting a hole in the casing, or using chemical to erode the wellbore casing.
 23. The method of claim 17, further comprising forming a hole through a wellbore casing and further lowering said tools under rotation so as to cut through any adjacent cement and into the earthen formation.
 24. The method of claim 17, further comprising pumping fluid to a location beneath the downhole tool assembly and at a sufficient velocity so as either suspend formation cuttings within the wellbore or to lift the cuttings to the surface.
 25. The method of claim 17, further comprising a means to vibrate at least a portion of the downhole assembly so as to mitigate the cutting head and/or flexible tubular member assembly from becoming stuck in the borehole.
 26. The method of claim 17, wherein the wellbore is an open hole wellbore and a borehole is formed into the earthen formation in a direction lateral to the open hole wellbore.
 27. A method for cutting laterally into an earthen formation from a cased wellbore comprising: positioning a guide assembly, capable of directing a downhole tool assembly adjacent to an earthen formation, within a wellbore; forming a hole in the wellbore casing; guiding a downhole tool assembly comprising a flexible tubing circumscribing a series of interconnectable drive segments, wherein the flexible tubing forms at least one inner passageway, through a channel defined by a guide assembly and directing the downhole tool assembly at the hole formed through the wellbore casing, wherein the downhole tool assembly is coupled to a conduit, such that the conduit and downhole tool assembly are in fluid communication; pumping one or more fluids through the conduit and the downhole tool assembly; activating a rotational source, wherein a torque is applied to the series of interconnectable drive segments; translating the torque to a cutting head of the downhole tool assembly, wherein the torque causes the cutting head to rotate; and guiding the downhole assembly through the hole in the wellbore casing and cutting a borehole into the earthen formation with the cutting head in a direction lateral to the wellbore.
 28. The method of claim 27, wherein the rotational source is activated by the fluid flow through the conduit into the rotational source.
 29. The method of claim 1, wherein the interconnectable drive segments comprise mating ends of adjoining links forming a universal joint allowing rotation about 2 axes on each end.
 30. The method of claim 1, wherein the interconnectable drive segments comprise mating ends of adjoining links joined together by a pin and socket mechanism allowing rotation in multiple axes on each end. 